Hydro-mechanical downhole tool

ABSTRACT

A downhole tool includes a body supported from a running string; and a releasing assembly for releasing from set liner hanger portions of the tool to be retrieved to the surface. The releasing assembly includes a connecting member for engaging the tool with a liner hanger, a piston hydraulically moveable in response to fluid pressure within the tool body from a lock position to a release position for releasing the connecting member, and a clutch for rotationally releasing the tool body from the liner hanger. Rotation of the running string moves a nut upward along the body so that the running string may then be picked up to disengage the tool from the liner hanger.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a continuation of, and claims priority to,co-pending U.S. patent application Ser. No. 13/413,828, filed Mar. 7,2012, and entitled “Hydro-Mechanical Downhole Tool”, and claims thebenefit of related U.S. Provisional Application Ser. No. 61/452,568,filed Mar. 14, 2011. The disclosures of each of the foregoing areincorporated by reference herein in its entirety.

BACKGROUND

Typically, in the drilling of a well, a borehole is drilled from theearth's surface to a selected depth and a string of casing is suspendedand then cemented in place within the borehole. A drill bit is thenpassed through the initial cased borehole and is used to drill a smallerdiameter borehole to an even greater depth. A smaller diameter casing isthen suspended and cemented in place within the new borehole. Generally,this is repeated until a plurality of concentric casings are suspendedand cemented within the well to a depth which causes the well to extendthrough one or more hydrocarbon producing formations.

Oftentimes, rather than suspending a concentric casing from the bottomof the borehole to the surface, a liner may be hung either adjacent thelower end of a previously suspended and cemented casing, or from apreviously suspended and cemented liner. A liner hanger is used tosuspend the liner within the lower end of the previously set casing orliner. A setting tool disposed on the lower end of a work string isreleasably connected to the liner hanger that is coupled with the top ofthe liner. The liner hanger, liner, setting tool, and other componentsare generally part of a liner hanger assembly.

Another component, such as a liner top packer, may also be part of theliner hanger assembly, which may be used to seal the liner in the eventof a poor cement job or to prevent gas flow while the cement sets.Typically, the liner top packer is set down on top of the liner hanger,and the liner top packer is set by the setting tool to seal the annulusbetween the liner and the previously set casing or liner. Liner toppackers run with liner hangers typically include a tubular member with abore in it that is coupled with the top end of the packer.

This tubular member is commonly referred to as a polished borereceptacle (“PBR”) or a tieback receptacle (“TBR”). Because the linerdoes not run to the surface, the liner hanger has the ability to receivethe PBR or TBR to connect the liner with a string of casing that extendsfrom the liner hanger back to the surface. There is typically a seal orseal stack between the PBR and the body of the packer that allows axialmotion of the PBR relative to the liner top packer body. A standard sealstack includes a plurality of annular spaced seals that fit within theinterior of the PBR. Often, a PBR is coupled into an upper end of thepacker, and production tubing is strung into the PBR with an appropriateseal to prevent leakage between the interior of the PBR and theproduction tubing.

Various types of liner hangers have been proposed for hanging a linerfrom a casing string in a well. Most liner hangers are set with slipsactivated by the liner hanger running tool. Liner hangers with multipleparts pose a significant liability when one or more of the parts becomeloose in the well, thereby disrupting the setting operation and makingretrieval difficult. In addition, wellbores often have tight spots anddog legs through which the liner hanger maneuvers, increasing the riskof the liner hanger becoming stuck or coming apart. Other liner hangersand running tools cannot perform conventional cementing operationsthrough the running tool before setting the liner hanger in the well.

Other liner hangers have problems supporting heavy liners with theweight of one million pounds or more. Some liner hangers successfullysupport the liner weight, but do no reliably seal with the casingstring. After the liner hanger is set in the well, high fluid pressurein the annulus between the liner and the casing may blow by the linerhanger, thereby defeating its primary purpose.

Another significant problem with some liner hangers is that the runningtool cannot be reliably disengaged from the set liner hanger. Thisproblem with liner hanger technology concerns the desirability to rotatethe liner with the work string in the well, then disengage from the workstring when the liner hanger has been set to retrieve the running toolfrom the well. Prior art tools have disengaged from the liner hanger byright-hand rotation of the work string, although some operators forcertain applications prefer to avoid right-hand rotation of a workstring to release the tool from the set liner. In addition, operatorsare presented with the problem of debris entering the running toolduring disengagement of the liner.

Accordingly, there exists a need for an improved downhole tool that hasimproved torque to wash and ream through tight spots and dog legs withinthe wellbore, that may avoid pre-setting while running, and that is ableto more effectively maneuver through tight areas in the wellbore.

SUMMARY

In one aspect, the embodiments disclosed herein relate to a downholetool that contains a body supported from a running string; and areleasing assembly for releasing from set liner hanger portions of thetool to be retrieved to the surface. The releasing assembly contains aconnecting member for engaging the tool with a liner hanger, a pistonhydraulically moveable in response to fluid pressure within the toolbody from a lock position to a release position for releasing theconnecting member, and a clutch for rotationally releasing the tool bodyfrom the liner hanger. The rotation of the running string moves a nutupward along the body so that the running string may then be picked upto disengage the tool from the liner hanger.

In another aspect, embodiments disclosed herein relate to a method ofreleasing a running tool while supported on a running string from aliner hanger in a casing within a wellbore. The liner hanger is securedto a casing by a slip assembly to suspend the liner hanger from thecasing. The method includes providing a releasing assembly about a toolbody, wherein the releasing assembly includes a connecting member forengaging the running string with the liner hanger, a pistonhydraulically moveable in response to fluid pressure within the toolbody from a lock position to a release position for releasing theconnecting member, a clutch for rotationally connecting the tool bodywith the liner hanger; and pressurizing the running string to move thepiston to the release position for releasing the running string.

In another aspect, embodiments disclosed herein relate to a method ofsetting a downhole tool. The method includes running the downhole to adesired depth in a wellbore; setting a liner hanger; activatinghydraulically a setting tool; and compressing the setting tool. Thecompressing releases the setting tool from a liner.

Other aspects and advantages of embodiments of the invention will beapparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1A shows a downhole tool in accordance with embodiments disclosedherein.

FIG. 1B shows a cylinder assembly in accordance with embodimentsdisclosed herein.

FIG. 1C shows a downhole tool in accordance with embodiments disclosedherein.

FIG. 2A shows a downhole tool in a first position in accordance withembodiments disclosed herein.

FIG. 2B shows a cross-sectional view of a downhole tool in a firstposition in accordance with embodiments disclosed herein.

FIG. 3A shows a downhole tool in a second position in accordance withembodiments disclosed herein.

FIG. 3B shows a first cross-sectional view of a downhole tool in asecond position in accordance with embodiments disclosed herein.

FIG. 4A shows a downhole tool in a third position in accordance withembodiments disclosed herein.

FIG. 4B shows a cross-sectional view of a downhole tool in a thirdposition in accordance with embodiments disclosed herein.

FIG. 5 shows a downhole tool in a fourth position in accordance withembodiments disclosed herein.

FIG. 6 shows a downhole tool in a fifth position in accordance withembodiments disclosed herein.

DETAILED DESCRIPTION

In some aspects, embodiments disclosed herein relate to downhole tools.In some aspects, embodiments disclosed herein relate to downhole toolshaving a packer or a packer and liner hanger. In certain aspects,embodiments disclosed herein relate to downhole tools having a packer,liner hanger, and setting adaptor.

In some aspects, embodiments disclosed herein relate to downhole toolshaving improved torque to run liner downhole. In certain aspects,embodiments disclosed herein relate to downhole tools having improvedreliability for release of a setting adaptor.

In some aspects, embodiments disclosed herein relate to hydro-mechanicaldownhole tools. In some aspects, embodiments disclosed herein relate todownhole tools having mechanical mechanisms to set a liner and ahydraulic lock to release a setting tool.

In other aspects, embodiments disclosed herein relate to methods andapparatus for drilling and completing well bores. More specifically,embodiments disclosed herein relate to methods and apparatus for runningliners downhole. In certain aspects, embodiments disclosed herein relateto methods and apparatus for hanging and/or setting liners in awellbore.

Embodiments disclosed herein are described below with terms designatingorientation in reference to a vertical wellbore. These terms designatingorientation should not be deemed to limit the scope of the disclosure.For example, embodiments of the disclosure may be with reference to anon-vertical wellbore, such as a horizontal or lateral wellbore. It isto be further understood that the various embodiments described hereinmay be used in various orientations, such as inclined, inverted,horizontal, vertical, etc., and in other environments, such as sub-seawells, without departing from the scope of the present disclosure. Theembodiments are described merely as examples of useful applications,which are not limited to any specific details of the embodiments herein.

In addition, other directional terms, such as “above,” “below,” “upper,”“lower,” etc., are used for convenience in referring to the accompanyingdrawings. In general, “above,” “upper,” “upward,” and similar termsrefer to a direction toward the earth's surface from below the surfacealong a wellbore, and “below,” “lower,” “downward,” and similar termsrefer to a direction into the Earth from the surface (i.e., into thewellbore), but is meant for illustrative purposes only, and the termsare not meant to limit the disclosure.

To hang a liner, a downhole tool may initially be attached to the lowerend of a work string and releasably connected to the liner toppacker/setting adapter, from which the liner is suspended for loweringinto the wellbore beneath the previously set casing or liner. The linertop packer/setting adapter may include, but is not limited to, a packer,liner, or setting adapter. The assembly may be run downhole at a ratethat does not adversely affect the well formations or the downhole tool.

Referring to FIG. 1A, a downhole tool in accordance with embodimentsdescribed herein is shown. Embodiments of a downhole tool 60 disclosedherein may include a body 40 interfacing with hydraulic and mechanicalcomponents. In some embodiments, body 40, which may include a mandrel orother tubular, is used to transmit torque to other components of tool60. In some embodiments, a downhole tool 60 may include a packer (notshown) as described in U.S. Pat. No. 4,757,860.

Downhole tool 60 may include a shearing means having a gage ring 2interfacing with a lock ring 3, a set screw 4, a shear screw 5, and akey screw 6. The gage ring 2 may provide a larger diameter surface thanthe body 1 to prevent snagging or catching of components of the downholetool 60 on downhole surfaces as the downhole tool 60 is lowered into thewellbore. The gage ring 2 may be disposed above or below the lock ring3. Lock ring 3 may be used during compression to hold the gage ring 2 inplace.

In some embodiments, the downhole tool 60 may include a hydraulicallyactuated release mechanism, operable in conjunction with a right-handrotation of body 40, for releasing the downhole tool 60 from a liner toppacker/setting adapter (not shown). In certain embodiments, thehydraulically actuated release mechanism may include a shear screw 5,which may be configured to be sheared at a pre-determined amount ofshearing force, as would be known by a person having ordinary skill inthe art. For example, the shearing force may be in the range of 5 to 50klbs (kilopounds). In some embodiments, the shear screw 5 may beconfigured to shear upon a shearing force in excess of 40 klbs. In otherembodiments, the shear screw 5 may be configured to shear upon ashearing force in excess of 12 klbs.

In some embodiments, the hydraulically actuated release mechanism mayinclude a cylinder assembly 50. FIG. 1B illustrates a cylinder assembly50 in accordance with embodiments described herein. In some embodiments,cylinder assembly 50 may be disposed laterally through body 40 orconcentrically disposed within body 40. In certain embodiments, cylinderassembly 50 may include a hydraulic cylinder 7 interfacing with sealrings and o-rings, for example, seal split ring 8, seal ring 9, o-ring11, o-ring backup 10, and o-ring 12. In some embodiments, seal rings maybe formed of a material having substantial elasticity to span certainportions of body 40. In certain embodiments, the hydraulic cylinder 7may include an actuator piston or ram (not shown) slidably engaged withbody 40. In some embodiments, the shear screw 5 may be disposedlaterally through the body 40, and engage the surface of body 40. Inother embodiments, hydraulic cylinder 7 may be pressurized using a balldrop method, explained in detail below. In certain embodiments,premature release of the liner top packer/setting adapter may beprevented because torsion is stored in cylinder assembly 50 and is nottransmitted to the running nut 23 until the hydraulic mechanism isactivated. In other words, cylinder assembly 50 may act to preventpremature release of liner top packer/setting adapter from downhole tool60.

Returning to the exemplary downhole tool illustrated in FIG. 1A, in someembodiments, a top clutch 13 may interface with washer 29, stop ring 30,cover ring 31, external ring 32, key screw 15, middle clutch 14, andbottom clutch 16, to lock one or more dogs. In some embodiments, the oneor more dogs may include a torque dog spring 20, a torque dog 17, atorque dog clamp 18, and a capscrew 19, which may act in conjunction toengage torque dog 17. In certain embodiments, the one or more dogs maybe concentrically contained within an outer cylindrical housing. In someembodiments, top clutch 13, middle clutch 14, and bottom clutch 16 mayeach rotatably lock torque dog 17 such that rotation of body 40 resultsin the movement of one or more downhole components. Thus, thedisposition of top clutch 13, middle clutch 14, and bottom clutch 16convert the rotational movement of body 40 to a reciprocated motion andeffectively function as a cam. In alternate embodiments, cover ring 31and external ring 32 may not be required. For example, referring brieflyto FIG. 1C, downhole tool 60 includes a key 55 disposed between topclutch 13 and middle clutch 14.

In certain embodiments, movement of body 40 may allow running nut 23 tomove upward along right-hand threads due to right-hand rotation. In someembodiments, the internal flow path/bypass of running nut 23 mayadvantageously allow for debris to be removed from the interior space ofa section 44 as the running nut 23 is threaded and/or unthreaded. Oncethe running nut 23 is unthreaded, the downhole tool 60 may be movedtoward the wellbore surface to disengage the downhole tool 60 from theliner top packer/setting adapter.

In some embodiments, downhole tool 60 may energize torque dog 17 using aspring assembly 21 in conjunction with key 22, which interface withrunning nut 23, set screw 24, o-rings 25 and 26, standing valve profile27, and bottom sub 28. In some embodiments, the spring assembly 21 andkey 22 may act to transfer torque to running nut 23. In certainembodiments, exterior threads of running nut 23 may attach to a linertop packer/setting adapter (not shown) such that downhole tool 60 isattached to the liner top packer/setting adapter.

In some embodiments, components of downhole tool 60 may permit theoperator to achieve an improved torque while running downhole tool 60down the wellbore and/or setting the liner top packer/setting adapter.The improved torque may allow for higher compression and improvedmitigation of tight spots and dog legs within the wellbore. In certainembodiments, downhole tool 60 may achieve a torque in the range of25,000 to 75,000 foot pounds (ft/lb) of force. In certain embodiments,downhole tool 60 may achieve a torque in excess of 25,000 ft/lb, or inexcess of 40,000 ft/lb, or in excess of 50,000 ft/lb of force.

Downhole tool 60 may also include other various design features such asvarious seals, washers, key screws and other various components tofurther facilitate the operation of the tool. In one embodiment, one ormore pins 35 may be disposed on top clutch 13. In certain embodimentsguides may be of various geometries, such as round, rectangular, square,etc. In certain embodiments, substantially square pins 35 may be used toreduce point contact.

FIG. 2A shows a downhole tool in a first position in accordance withembodiments disclosed herein. In FIG. 2A, downhole tool 260 is ready toattach to a liner top packer/setting adapter (not shown). In someembodiments, top clutch 213 engages to compresses torque dog 217, whichtransmits a rotational force to portion 244, and more specifically,running nut 223. In exemplary embodiments, top clutch 213 may rotate tothe left 30 degrees to disengage torque dog 217 and transmit therotational force. In some exemplary embodiments, the rotational forcecauses running nut 223 to rotate four times to the left and connect thedownhole tool 260 to the liner top packer/setting adapter.

FIG. 2B shows a cross-sectional view of a downhole tool in a firstposition in accordance with embodiments disclosed herein. Morespecifically, FIG. 2B is a cross-sectional view taken through positionB-B of downhole tool 260 prior to connection of the liner toppacker/setting adapter. For example, FIG. 2B shows a view of the clutchassembly prior to the top clutch 213 being engaged to compress torquedog 217 and effectuate rotational movement of running nut 223. Asillustrated in FIG. 2A, torque dog 217 is disengaged and not viewablethrough window 218.

FIG. 3A shows a downhole tool in a second position in accordance withembodiments disclosed herein. In some embodiments, FIG. 3A showsdownhole tool 360 after the liner top packer/setting adapter (not shown)is attached to downhole tool 360 such that downhole tool 360 is in a runin position. For example, top clutch 313 has been engaged and runningnut 323 has rotated to attach the liner top packer/setting adapter toportion 344. Torque dog 317 is also engaged and viewable through window318. In certain embodiments, the downhole tool 360 shown in FIG. 3A isrun downhole and remains in the run in position until the desiredwellbore depth is reached. In certain embodiments, the downhole tool 360shown in FIG. 3A is prepared to place the liner top packer/settingadapter at a desired location downhole.

FIG. 3B shows a first cross-sectional view of a downhole tool in asecond position in accordance with embodiments disclosed herein. Morespecifically, FIG. 3B is a cross-sectional view taken through positionB-B of downhole tool 360 after connection of the liner toppacker/setting adapter. In some embodiments, FIG. 3B shows the clutchassembly after top clutch 313 has been engaged and the liner toppacker/setting adapter is attached.

FIG. 4A shows a downhole tool in a third position in accordance withembodiments disclosed herein. In FIG. 4A, downhole tool 460 is set to anextended position to prepare to release the liner top packer/settingadapter (not shown). In some embodiments, middle clutch 414 is engaged,effectuating rotational movement of portion 444 and more specifically,running nut 423. An applied rotational force may thus cause running nut423 to rotate to the right. In some embodiments, actuation of top clutch413 prepares downhole tool 460 to be released from the liner toppacker/setting adapter and subsequently pulled toward the surface of thewellbore (not shown). In certain embodiments, bottom clutch 416 cannotmove because it is adjacent to the liner top packer/setting adapter.

FIG. 4B shows a cross-sectional view of a downhole tool in a thirdposition in accordance with embodiments disclosed herein. Morespecifically, FIG. 4B is a cross-sectional view taken through positionB-B of downhole tool 460. In some embodiments, FIG. 4B is across-sectional view of the clutch assembly after middle clutch 414 hasbeen engaged. For example, FIG. 4B shows a view of the clutch assemblyafter the top clutch 413 has been engaged (and ready to compress torquedogs 417) to effectuate rotational movement of portion 444, and morespecifically, running nut 423.

FIG. 5 shows a downhole tool in a fourth position in accordance withembodiments disclosed herein. In some embodiments in FIG. 5, liner toppacker/setting adapter (not shown) is unthreaded in preparation to pulldownhole tool 560 back to the wellbore surface. In certain embodiments,portion 544, and more specifically, running nut 523, is rotated to theright to disengage the liner top packer/setting adapter. In someembodiments, the rotation of running nut 523 releases downhole tool 560from liner top packer/setting adapter and pulled back to the surface ofthe wellbore.

FIG. 6 shows a downhole tool in a fourth position in accordance withembodiments disclosed herein. In some embodiments in FIG. 6, a ball dropis performed to shear the shear screw 605 and ready downhole tool 660 tobe rotationally disengaged from the liner top packer/setting adaptor andpulled back to the wellbore surface. In other embodiments, a ball dropis performed to shear the shear screw 605 and ready portion 644 to bereleased from the liner top packer/setting adapter by a rotational forceon running nut 623. In certain embodiments, hydraulic cylinder 607 maybe pressurized using a ball drop method. In some embodiments, a balldrop within body 640 may increase fluid pressure to the piston, asexplained below. The fourth position is functionally between the firstand second position, described above.

Different methods may be used to increase fluid pressure to actuatecomponents of downhole tool 660. In one embodiment, a method may includeperforming a ball (not shown) drop, including but not limited to, colletfingers, a ball valve, and a mechanically expanding ball seat. Forexample, downhole tool 660 may use collet fingers (not shown) as a ballseat, such that an expansion of the collet fingers may allow the ball todrop through the expanded seat. As another example, a rotating ballvalve may be used such that a small hole in the valve acts as a seat forthe ball and an increase in pressure causes rotation of the ball,allowing the ball to drop. As a further example, a ball drop method mayinclude dropping a ball (not shown) from handling equipment at thewellbore surface (not shown) into one or more seats (not shown) withindownhole tool 660.

In some embodiments, as the ball moves through the downhole tool 660, itmay cause fluid pressure to increase when seated. Upon application ofpressure to the seated ball, one or more shear pins (for example, shearscrew 605) may be sheared, thereby disengaging the downhole tool 660from the liner top packer/setting adapter. In some embodiments, theshearing of the shear screw 605 and passage of fluid through the one ormore ports may act upon one or more pistons (not shown) connected to topclutch 616 to disengage the torque dogs, thereby allowing transmissionof rotational force to portion 644, rotating running nut 623 and therebyreleasing the liner top packer/setting adapter. Once the shear screw 605is sheared, the ball may then be moved into a ball diverter (not shown),allowing fluids to be circulated through the downhole tool 660, which isprepared for cementing steps.

In some embodiments, hydraulic cylinder 607 may be pressurized to applyforce to an actuator piston (not shown). Once the force exceeds apre-determined set point, the piston may axially move the upper body 640in order to shear the shear screw 605.

Advantageously, embodiments disclosed herein provide for an improvedability to mitigate tight spots and dog legs within the wellbore. Saidanother way, embodiments disclosed herein may advantageously allow animproved ability to wash and ream in the wellbore due to improvedtorque. In addition, some embodiments may advantageously use a bearingfor rotation of the liner top packer/setting adaptor.

Further advantages include the hydraulic mechanism of embodimentsdisclosed herein. Some embodiments disclosed herein may advantageouslyprevent premature release of the downhole tool by use of the hydraulicmechanism. Advantageously, in embodiments disclosed herein, thehydraulic mechanism may act as a hydraulic lock whereby prematurerelease of the liner top packer/setting adaptor is prevented, thusproviding improved reliability.

Advantageously, embodiments disclosed herein provide an internal flowpath of a running nut, thereby allowing removal of debris from internalcomponents of the downhole tool as the running nut is threaded and/orunthreaded. Further advantages include the improved alignment of thedownhole tool with the liner top packer/setting adaptor provided byengagement of the one or more dogs.

Also advantageously, embodiments of the present application may providea timing feature, such that, for example, eight turns of the body startsrotation of a bottom clutch, while, for example, four turns may beeffectuated to engage top and middle clutches. Those of ordinary skillin the art will appreciate that the number of rotations required toengage and disengage top, middle, and bottom clutches may vary inaccordance with specific design requirements.

While embodiments of the invention have been described with respect to alimited number of embodiments, those skilled in the art, having benefitof this disclosure, will appreciate that other embodiments can bedevised which do not depart from the scope of the embodiments asdisclosed herein. Accordingly, the scope of embodiments of the inventionshould be limited only by the attached claims.

What is claimed:
 1. A downhole tool release assembly for releasing froma set liner hanger portions of the tool to be retrieved to the surfaceby a running string, the release assembly comprising: a connectingmember for engaging the tool with a liner hanger, wherein the toolincludes a tool body; a piston hydraulically moveable in response tofluid pressure within the release assembly from a lock position to arelease position for releasing the connecting member; and a plurality ofclutches for rotationally releasing the tool body from the liner hanger,wherein rotation of the running string moves a running nut upward alongthe body to disengage the tool from the liner hanger as the runningstring is picked up.
 2. The release assembly of claim 1, wherein thefluid pressure within the release assembly is adjusted by a ball drop.3. The release assembly of claim 2 further comprising a shearing device.4. The release assembly of claim 3, wherein a pressure differentialcaused by the ball drop creates a force on the piston that exceeds apredetermined set point of the shearing device.
 5. The release assemblyof claim 1, further comprising a plurality of dogs.
 6. The releaseassembly of claim 1, wherein the release assembly achieves a torque ofat least 40,000 ft/lb when supported by a running string.
 7. The releaseassembly of claim 1, further comprising a shear screw.
 8. The releaseassembly of claim 7, wherein the shear screw is configured to shear in arange between about 5 and about 50 kilopounds.